Downhole completion tool

ABSTRACT

A downhole tool and method of operation thereof is provided. The downhole tool may be configured to permit fluid communication between a combined flowbore of the casing string and the downhole tool and the subterranean formation or wellbore, or both, after a pressure test has been completed, a second threshold pressure is reached or applied, and a third threshold pressure has been applied to the downhole tool.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. Utility patent applicationhaving Ser. No. 14/098,012, which was filed Dec. 5, 2013, which claimsthe benefit of U.S. Provisional Patent Application having Ser. No.61/883,156, which was filed Sep. 26, 2013. These priority applicationsare hereby incorporated by reference in their entirety into the presentapplication to the extent consistent with the present application.

BACKGROUND

During the completion process of a hydrocarbon-producing well in asubterranean formation, a conduit, such as a casing string, may be runinto the wellbore to a predetermined depth and, in some instances,cemented in place to secure the casing string. Various “zones” in thesubterranean formation may be isolated via the placement of one or morepackers, which may also aid in securing the casing string and anycompletion equipment, e.g., fracturing equipment, in place in thewellbore. Following the placement and securing of the casing string andany completion equipment in the wellbore, a “pressure test” is typicallyperformed to ensure that a leak or hole has not developed during theplacement of the casing string and completion equipment.

Generally, a pressure test is conducted by pumping a fluid into aflowbore of the casing string, such that a predetermined pressure,typically related to the rated casing pressure, is applied to the casingstring and completion equipment and maintained to ensure that a hole orleak does not exist in either. To do so, the casing string is configuredsuch that no fluid passages out of the casing string are provided; thus,no ports or openings of the completion equipment, in addition to anyother potential routes of fluid communication, may be open or available.After the pressure test is completed, further completion or productionof the hydrocarbon-producing well may commence.

Accordingly, in order to either retrieve hydrocarbons and other fluidsfrom the subterranean formation or to stimulate the subterraneanformation, for example, via fracturing, one or more flowpaths may becreated to provide communication between the flowbore and the wellboreor subterranean formation, or both, through the casing string. Onemethod of providing such flowpaths includes the utilization of aperforating gun. In such a method, a perforating gun, typicallyincluding a string of shaped charges, is run down to the desired depthon, for example, E-line, coil tubing, or slickline. The shaped chargesare detonated, thereby creating perforations in the casing string andhence the flowpaths between the subterranean formation, wellbore, andthe flowbore. However, one disadvantage of perforating is “skin damage,”where debris from the perforations may hinder productivity of the well.Another disadvantage of perforating is the cost and inefficiency ofhaving to make a separate trip to run the perforating gun downhole.

Accordingly, in an effort to reduce the number of trips, another methodof providing such flowpaths includes the utilization of a pressureactivated tool, such as a differential valve, in the casing string.Generally, the differential valve is designed to open, creating suchflowpaths, once a threshold pressure is reached; however, thedifferential valves generally may often be inaccurate as to the pressureat which they open and such valves also do not allow for closing oncethey have been opened. Thus, once a pressure test has been performed ator near the threshold pressure, the well will be open, thereby impairingor potentially eliminating the ability to control the wellbore, therebyposing various risks, such as blow-outs or the loss of hydrocarbons.

What is needed, then, is a downhole completion tool capable ofundergoing a pressure test and subsequently providing flowpaths forproduction or stimulation fluids while maintaining wellbore controlafter the pressure test is completed.

SUMMARY

Embodiments of the disclosure may provide a downhole tool. The downholetool may include a housing at least partially defining a flowboretherethrough and a plurality of fluid apertures. The downhole tool mayalso include an inner annular casing disposed in the housing anddefining in conjunction with the housing an annular space. The downholetool may further include an annular cover disposed in the annular spaceand configured to be displaced by a first piston at a first pressureapplied to the flowbore and a biasing member at a second pressureapplied to the flowbore. The downhole tool may also include a secondpiston at least partially disposed in the annular space and configuredto be displaced by a force provided by a third pressure applied to theannular space via the flowbore, such that the plurality of fluidapertures and the flowbore are fluidly coupled.

Embodiments of the disclosure may further provide a method of servicinga subterranean formation. The method may include applying a firstpressure to a first piston via a first port defined in an inner annularcasing of a downhole tool including a housing at least partiallydefining a flowbore extending axially therethrough and in fluidcommunication with the first port. The method may also includedisplacing an annular cover axially via a force provided by the firstpressure on the first piston, the annular cover shearing a firstretention member configured to retain the annular cover prior to theapplication of the first pressure. The method may further includedisplacing a locking ring detachably attached to the annular cover, suchthat the locking ring detaches from the annular cover. The method mayalso include decreasing the first pressure to a second pressure suchthat the annular cover is axially displaced and the flowbore is fluidlycoupled with an annular space defined at least in part by the housingand the inner annular casing. The method may further include applying athird pressure to the annular space via the flowbore. The method mayalso include displacing a second piston axially via a force provided bythe third pressure on the second piston. The second piston may shear asecond retention member configured to retain the second piston prior tothe application of the third pressure, thereby fluidly coupling thesubterranean formation and the flowbore via a plurality of housingapertures defined in the housing.

Embodiments of the disclosure may further provide a downhole toolconfigured to be disposed in a wellbore defined in a subterraneanformation. The downhole tool may include a housing at least partiallydefining a flowbore therethrough and a plurality of fluid apertures. Thedownhole tool may also include an inner annular casing disposed in thehousing and defining in conjunction with the housing an annular space.The inner annular casing may further define a casing flowpath and afirst port configured to fluidly couple the flowbore and the casingflowpath. The downhole tool may further include an annular coverdisposed in the annular space and configured to prevent fluidcommunication between the annular space and the flowbore during theapplication of a first pressure and to permit fluid communicationbetween the annular space and the flowbore during the application of asecond pressure and a third pressure. The downhole tool may also includea lower piston configured to engage the inner annular casing and preventfluid communication between the flowbore and the wellbore via theplurality of fluid apertures at the application of the first pressureand the second pressure. The lower piston may be further configured toslidingly disengage with the inner annular casing and thereby permitfluid communication between the flowbore and the wellbore via theplurality of fluid apertures at the application of the third pressure.The downhole tool may further include an upper piston disposed in thecasing flowpath and the annular space and configured to axially displacethe annular cover at the application of the first pressure. The downholetool may also include a biasing member configured to axially displacethe upper piston and the annular cover to permit fluid communicationbetween the annular space and the flowbore at the application of thesecond pressure. The downhole tool may further include a plurality ofretention members. A first retention member of the plurality ofretention members may be configured to retain the upper piston prior tothe application of the first pressure and a second retention member ofthe plurality of retention members may be configured to retain the lowerpiston prior to the application of the third pressure.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detaileddescription when read with the accompanying Figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIG. 1 illustrates a partial cutaway view of a wellbore defined in asubterranean formation, the wellbore having a casing string disposedtherein and including one or more packers, a float shoe, and a downholecompletion tool coupled thereto, according to one or more embodimentsdisclosed.

FIG. 2A illustrates a cross-sectional view of the downhole completiontool of FIG. 1 coupled to a top sub component and a bottom sub componentof the casing string, the downhole tool shown as configured in aninitial position prior to the application of a first threshold pressure,according to one or more embodiments disclosed.

FIG. 2B illustrates an enlarged view of the encircled portion of thedownhole completion tool labeled “2B” in FIG. 2A, according to one ormore embodiments disclosed.

FIG. 2C illustrates a cross-sectional view of the downhole completiontool of FIG. 1 coupled to the top sub component and the bottom subcomponent of the casing string, the downhole tool shown as configuredafter the application of the first threshold pressure, according to oneor more embodiments disclosed.

FIG. 2D illustrates an enlarged view of the encircled portion of thedownhole completion tool labeled “2D” in FIG. 2C, according to one ormore embodiments disclosed.

FIG. 2E illustrates a cross-sectional view of the downhole completiontool of FIG. 1 coupled to the top sub component and the bottom subcomponent of the casing string, the downhole tool shown as configuredafter the bleed down of the first threshold pressure to a secondthreshold pressure, according to one or more embodiments disclosed.

FIG. 2F illustrates an enlarged view of the encircled portion of thedownhole completion tool labeled “2F” in FIG. 2E, according to one ormore embodiments disclosed.

FIG. 2G illustrates a cross-sectional view of the downhole completiontool of FIG. 1 coupled to the top sub component and the bottom subcomponent of the casing string, the downhole tool shown as configuredafter the application of a third threshold pressure, according to one ormore embodiments disclosed.

FIG. 2H illustrates an enlarged view of the encircled portion of thedownhole completion tool labeled “2H” in FIG. 2G, according to one ormore embodiments disclosed.

FIG. 3A illustrates a cross-sectional view of the downhole completiontool of FIG. 1 coupled to the top sub component and the bottom subcomponent of the casing string, the downhole tool shown as configured inan initial position prior to the application of a first thresholdpressure, according to one or more embodiments disclosed.

FIG. 3B illustrates an enlarged view of the encircled portion of thedownhole completion tool labeled “3B” in FIG. 3A, according to one ormore embodiments disclosed.

FIG. 3C illustrates a cross-sectional view of the downhole completiontool of FIG. 1 coupled to the top sub component and the bottom subcomponent of the casing string, the downhole tool shown as configuredafter the application of the first threshold pressure, according to oneor more embodiments disclosed.

FIG. 3D illustrates an enlarged view of the encircled portion of thedownhole completion tool labeled “3D” in FIG. 3C, according to one ormore embodiments disclosed.

FIG. 3E illustrates a cross-sectional view of the downhole completiontool of FIG. 1 coupled to the top sub component and the bottom subcomponent of the casing string, the downhole tool shown as configuredafter the bleed down of the first threshold pressure to a secondthreshold pressure, according to one or more embodiments disclosed.

FIG. 3F illustrates an enlarged view of the encircled portion of thedownhole completion tool labeled “3F” in FIG. 3E, according to one ormore embodiments disclosed.

FIG. 3G illustrates a cross-sectional view of the downhole completiontool of FIG. 1 coupled to the top sub component and the bottom subcomponent of the casing string, the downhole tool shown as configuredafter the application of a third threshold pressure, according to one ormore embodiments disclosed.

FIG. 3H illustrates an enlarged view of the encircled portion of thedownhole completion tool labeled “3H” in FIG. 3G, according to one ormore embodiments disclosed.

FIG. 4 is a flowchart illustrative of a method for servicing asubterranean formation, according to one or more embodiments disclosed.

DETAILED DESCRIPTION

It is to be understood that the following disclosure describes severalexemplary embodiments for implementing different features, structures,or functions of the invention. Exemplary embodiments of components,arrangements, and configurations are described below to simplify thepresent disclosure; however, these exemplary embodiments are providedmerely as examples and are not intended to limit the scope of theinvention. Additionally, the present disclosure may repeat referencenumerals and/or letters in the various exemplary embodiments and acrossthe Figures provided herein. This repetition is for the purpose ofsimplicity and clarity and does not in itself dictate a relationshipbetween the various exemplary embodiments and/or configurationsdiscussed in the various Figures. Moreover, the formation of a firstfeature over or on a second feature in the description that follows mayinclude embodiments in which the first and second features are formed indirect contact, and may also include embodiments in which additionalfeatures may be formed interposing the first and second features, suchthat the first and second features may not be in direct contact.Finally, the exemplary embodiments presented below may be combined inany combination of ways, i.e., any element from one exemplary embodimentmay be used in any other exemplary embodiment, without departing fromthe scope of the disclosure.

Additionally, certain terms are used throughout the followingdescription and claims to refer to particular components. As one skilledin the art will appreciate, various entities may refer to the samecomponent by different names, and as such, the naming convention for theelements described herein is not intended to limit the scope of theinvention, unless otherwise specifically defined herein. Further, thenaming convention used herein is not intended to distinguish betweencomponents that differ in name but not function. Additionally, in thefollowing discussion and in the claims, the terms “including” and“comprising” are used in an open-ended fashion, and thus should beinterpreted to mean “including, but not limited to.” All numericalvalues in this disclosure may be exact or approximate values unlessotherwise specifically stated. Accordingly, various embodiments of thedisclosure may deviate from the numbers, values, and ranges disclosedherein without departing from the intended scope. Furthermore, as it isused in the claims or specification, the term “or” is intended toencompass both exclusive and inclusive cases, i.e., “A or B” is intendedto be synonymous with “at least one of A and B,” unless otherwiseexpressly specified herein.

Unless otherwise specified, use of the terms “up,” “upper,” “upward,”“uphole,” “upstream,” or other like terms shall be construed asgenerally toward the surface of the formation or the surface of a bodyof water; likewise, use of “down,” “lower,” “downward,” “downhole,”“downstream,” or other like terms shall be construed as generally awayfrom the surface of the formation or the surface of a body of water,regardless of the wellbore orientation. Use of any one or more of theforegoing terms shall not be construed as denoting positions along aperfectly vertical axis.

Turning now to the Figures, FIG. 1 illustrates a partial cutaway view ofa wellbore 10 having a casing string 12 disposed therein and includingone or more packers 14, a float shoe 16, and a downhole completion tool18 coupled thereto, according to one or more embodiments disclosed. Thewellbore 10 is defined by a subterranean formation 20 and is utilizedfor the retrieval of hydrocarbons therefrom. As illustrated, at least aportion of the wellbore 10 is oriented in a horizontal direction in thesubterranean formation 20; however, embodiments in which the wellbore 10is oriented in a conventional vertical direction are contemplatedherein, and the depiction of the wellbore 10 in a horizontal or verticaldirection is not to be construed as limiting the wellbore 10 to anyparticular configuration. Accordingly, in some embodiments, the wellbore10 may extend into the subterranean formation 20 in a verticaldirection, thereby having a vertical wellbore portion, and may deviateat any angle from the vertical wellbore portion, thereby having adeviated or horizontal wellbore portion. Thus, the wellbore 10 may be orinclude portions that may be vertical, horizontal, deviated, and/orcurved.

As shown, the wellbore 10 is in fluid communication with the surface 22via a rig 24 and/or other associated components positioned on thesurface 22 around the wellbore 10. The rig 24 may be a drilling rig or aworkover rig and may include a derrick 26 and a rig floor 28, throughwhich the casing string 12 is positioned within the wellbore 10. Inexample embodiments, the casing string 12 includes the downholecompletion tool 18 coupled to a first sub component 30 and a second subcomponent 32 (FIGS. 2A, 2C. 2E, 2G, 3A, 3C, 3E, and 3G) of the casingstring 12. The downhole completion tool 18 may be delivered to apredetermined depth and positioned in the wellbore 10 via the rig 24 toperform in part a particular servicing operation including, for example,fracturing the subterranean formation 20, expanding or extending aflowpath therethrough, and/or producing hydrocarbons from thesubterranean formation 20. In at least one embodiment, a portion of thecasing string 12 may be secured into position in the subterraneanformation 20 using cement. In another embodiment, the wellbore 10 may bepartially cased and cemented such that a portion of the wellbore 10 isuncemented.

The rig 24 may be a conventional drilling or workover rig and mayutilize a motor-driven winch and other associated equipment for loweringthe casing string 12 and the downhole completion tool 18 to the desireddepth. Although the rig 24 is depicted in FIG. 1 as a stationarydrilling or workover rig, it will be appreciated by one of ordinaryskill in the art that mobile workover rigs, wellbore servicing units(e.g., coil tubing units), and the like may be used to lower thedownhole completion tool 18 into the wellbore 10. Additionally, it willbe understood that the downhole completion tool 18 may be used in bothonshore and offshore environments.

As noted above, in some embodiments, the downhole completion tool 18 isreferred to as being coupled to components of a casing string 12, e.g.,first and second sub components 30,32; however, it will be appreciatedby one or ordinary skill in the art that the downhole completion tool 18may be incorporated into other suitable tubular members. In at least oneother embodiment, the downhole completion tool 18 may be incorporatedinto a liner. Further, the downhole completion tool 18 may beincorporated into a work string or like component.

Referring now to FIGS. 2A-2H and 3A-3H, the downhole completion tool 18may be configured as depicted to permit fluid communication between acombined flowbore 34 of the casing string 12 and downhole completiontool 18 and the subterranean formation 20 or wellbore 10, or both, aftera pressure test has been completed (i.e., at least a first thresholdpressure has been applied to the casing string 12 and the downholecompletion tool 18 and no leaks or holes exist), a second thresholdpressure is reached or applied, and a third threshold pressure has beenapplied to the downhole completion tool 18. The downhole completion tool18 may include a generally tubular-like, e.g., cylindrical, housing 36having the flowbore 34 extending axially therethrough. The downholecompletion tool 18 may further include a first end portion 38 and asecond end portion 40 and may define a plurality of housing apertures 41therebetween. As shown, the downhole completion tool 18 may be coupledto the first sub component 30 and the second sub component 32 of thecasing string 12, according to some embodiments disclosed. In formingthe coupling, the first end portion 38 of the housing 36 may includeinner threads configured to engage outer threads of the first subcomponent 30 and to further form a sealing relationship via a first subseal component 42, illustrated as an O-ring. Additionally, the secondend portion 40 of the housing 36 may include inner threads configured toengage outer threads of the second sub component 32 and to further forma sealing relationship via a second sub seal component 44, illustratedas an O-ring. Other coupling methods known to those of skill in the artare contemplated herein including, for example, clamps.

The first sub component 30 may be further coupled to another portion ofthe casing string 12, a packer 14, or other associated drilling orcompletion component(s). The second sub component 32 may be furthercoupled to another portion of the casing string 12, the float shoe 16,or other associated drilling or completion component(s). In an exemplaryembodiment, the downhole completion tool 18 may be coupled to the casingstring 12 proximate the end portion or “toe” of the casing string 12.

As shown in FIGS. 2A-2H and 3A-3H, the downhole completion tool 18 mayinclude an inner annular casing 46 and a lower piston 48 concentricallydisposed in the housing 36 and defining in conjunction the flowbore 34of the downhole completion tool 18. The lower piston 48 may beconfigured to slidingly fit against an inner surface 50 of the housing36 and may have a first end portion 52 configured to slidingly engage asecond end portion 54 of the inner annular casing 46 in a sealingrelationship. The second end portion 54 of the inner annular casing 46may form a shoulder 56 configured to receive and seat the first endportion 52 of the lower piston 48. The first end portion 52 of the lowerpiston 48 may define a plurality of grooves, such that a first sealcomponent 58, illustrated as an O-ring, may be disposed in a firstgroove to form the sealing relationship with the second end portion 54of the inner annular casing 46, and a second seal component 60,illustrated as an O-ring, may be disposed in a second groove to form asealing relationship between the first end portion 52 of the lowerpiston 48 and the cylindrical housing 36. A plurality of retentionmembers 62, illustrated as shear screws, may be utilized to retain thelower piston 48 seated and in a sealing relationship with the innerannular casing 46 prior to the third threshold pressure being appliedthereto. The shear screws 62 may be inserted or disposed incorresponding suitable boreholes in the housing 36 and boreholes in thelower piston 48. As appreciated by one of ordinary skill in the art, theshear screws may be configured to shear or break when a desiredmagnitude of force is applied thereto. Although the retention members 62are illustrated as shear screws, one or ordinary skill in the art willappreciate that the retention members 62 may be shear pins, lock rings,snap rings, or any other like component capable of retaining the lowerpiston 48 in the initial position.

The inner annular casing 46 further may define in conjunction with thecylindrical housing 36 an annular space 64 therebetween. In someembodiments, a biasing nut 66, a biasing member 68, a first annularcomponent 70, a second annular component 72, an annular cover 74, aplurality of seal components 76, 78, and at least a portion of an upperpiston 80 may be disposed within the annular space 64. The annular space64 may be in fluid communication with a casing flowpath 82 defined by afirst end portion 84 of the inner annular casing 46. The upper piston 80may include a piston head 86 and a piston rod 88, such that the pistonhead 86 may be disposed in the casing flowpath 82 and the piston rod 88may be partially disposed in each of the annular space 64 and the casingflowpath 82. The upper piston 80 may be further configured to axiallydisplace the annular cover 74 subject to forces applied to the pistonhead 86 by the first threshold pressure. The first end portion 84 of theinner annular casing 46 further defines a first port 90 in fluidcommunication with the casing flowpath 82 and the flowbore 34.

An end portion 92 of the piston rod 88 may be coupled or integral with afirst end portion 94 of the annular cover 74 and configured to actuatethe annular cover 74 such that the annular cover 74 moves axially withinthe annular space 64. One or more retention members 96, illustrated asshear screws, may be configured to retain the annular cover 74 in aninitial position prior to the application of the first thresholdpressure. The first annular component 70, illustrated as a shear ring inFIGS. 2A-2H and 3A-3H, may be disposed between the annular cover 74 andthe cylindrical housing 36 and may retain the shear screws 96. Inanother embodiment, the annular cover 74 may retain the shear screws asshown in FIGS. 3A-3H.

In some embodiments, the first annular component 70 and the annularcover 74 may be a unitary piece; however, in other embodiments, thefirst annular component 70 and the annular cover 74 are respectiveindividual components and arranged within the annular space 64 such thata fluid passageway 97 is defined therebetween, as shown in FIGS. 3A-3H.The shear screws 96 may be inserted or disposed in correspondingsuitable boreholes in the annular cover 74 and at least one of suitableboreholes in the first annular component 70 and suitable boreholes inthe inner annular casing 46. As appreciated by one of ordinary skill inthe art, the shear screws 96 may be configured to shear or break when adesired magnitude of force is applied thereto. Although the retentionmembers 96 are illustrated as shear screws, one or ordinary skill in theart will appreciate that the retention members 96 may be shear pins,lock rings, snap rings, or any other like component capable of retainingthe annular cover 74 in the initial position.

In the initial position, in one or more embodiments, the annular cover74 may cover a second port 98 defined in the inner annular casing 46 andprevent the second port 98 from fluidly communicating with the annularspace 64 as shown in FIGS. 2A-2D. In some embodiments, the annular cover74 may be an annular sleeve. The annular cover 74 may further define aplurality of grooves, each groove retaining a respective seal component76, 78, illustrated as an O-ring, to provide a sealing relationshipbetween the annular cover 74 and the inner annular casing 46, therebypreventing fluid communication between the second port 98 and theannular space 64.

A recessed end portion 100 of the first annular component 70 may form ashoulder 102 configured to seat the second annular component 72,illustrated as a locking ring, when the annular cover 74 is in theinitial position. The locking ring 72 may be detachably attached to asecond end portion 104 of the annular cover 74. In another embodiment,annular cover may include a plurality of components including a springspacer (not shown) spaced apart from a main body of the annular cover 74in the initial position. Accordingly, the locking ring 72 may bedetachably attached to the spring spacer adjacent the main body of theannular cover 74.

In the initial position, the locking ring 72 may be detachably attachedto the annular cover 74 such that the annular cover 74 is fixed. Therecessed end portion 100 of the first annular component 70 may furtherform a lip 106, such that the lip 106 may be configured to seat thelocking ring 72 after the locking ring 72 has been axially displaced.The locking ring 72 may be further configured to release or detach fromthe second end portion 104 of the annular cover 74 when seated on thelip 106. In an embodiment in which the first annular component 70 andannular cover 74 are a unitary piece, the annular space 64 may include aprotrusion disposed therein and integral or coupled with the innersurface 50 of the housing 36 to seat the locking ring 72 after thelocking ring 72 is displaced axially downstream by the unitary pieceincluding the shear ring 70 and the annular cover 74.

The biasing member 68, illustrated as a spring in the embodiments ofFIGS. 2A-2H and 3A-3H, may be disposed in the annular space 64 andconfigured to expand and compress based on the positioning of thebiasing nut 66 and the locking ring 72. The locking ring 72 in theinitial position may be seated on the shoulder 102 formed on the firstannular component 70 and is thereby positioned to compress the spring 68against the biasing nut 66, such that the spring 68 may store mechanicalenergy and is prohibited from forcing the axial displacement of theannular cover 74. The spring rate of the spring 68 may be based at leastin part on the pressure in the annular space 64 in which it is disposed.The positioning of the biasing nut 66 may also determine in part thethird threshold pressure to be applied to the downhole completion tool18.

The annular space 64 may be pressurized to be or include a pressurizedchamber. In an exemplary embodiment, the annular space 64 is apressurized chamber having a pressure substantially equal to oneatmospheric unit (1 atm). In another embodiment, the pressurized chambermay have a pressure greater than 1 atm. To provide the pressurizedchamber at atmospheric pressure, the pressurized chamber may be sealedprior to the downhole completion tool 18 being run downhole, such thatthe pressurized chamber may be maintained at atmospheric pressure at thepredetermined depth of the downhole completion tool 18 at the initialposition.

Operation of the downhole completion tool 18 may now be disclosedherein, according to at least some embodiments of the presentdisclosure. As shown in FIG. 1, the downhole completion tool 18 may bepositioned by “running in” the casing string 12 to the desired depth orlocation in the wellbore 10. As shown, the casing string 12 may includethe downhole completion tool 18, and may be integrated with or coupledto the first sub component 30 and the second sub component 32 as shownin the embodiments of FIGS. 2A-2H and 3A-3H. As such, the downholecompletion tool 18 and the casing string 12 have a common flowbore 34,through which fluid may be communicated to and/or from the surface 22.Accordingly, fluid introduced into the casing string 12 at the surface22 may flow through the downhole completion tool 18 and fluid introducedfrom the subterranean formation 20 to the downhole completion tool 18may flow through the casing string 12.

Depending on the design of the hydrocarbon-producing well, none, aportion of, or substantially all of the casing string 12 may be cementedin place to secure the casing string 12 in the wellbore 10. Optionally,one or more packers 14 and/or the float shoe 16 may be provided in thewellbore 10 as shown in FIG. 1. One of ordinary skill in the art willappreciate that other components may be disposed in the wellbore 10based on at least design choices and the subterranean formation 20. Uponcementing the casing string 12 in the wellbore 10, a pressure test maybe performed to ensure that no leaks or holes are present in thewellbore 10 that may compromise the integrity of thehydrocarbon-producing well.

As initially positioned in the wellbore 10 and prior to the initiationof the pressure test, the downhole completion tool 18 may be configuredas depicted in FIGS. 2A and 2B in at least one embodiment. In anotherembodiment, the downhole completion tool 18 may be configured asdepicted in FIGS. 3A and 3B. Accordingly, in either the embodiment ofFIGS. 2A and 2B or the embodiment of FIGS. 3A and 3B, the downholecompletion tool 18 may be referred to as being in a “run in” or initialposition. In the initial position, the first port 90 may be in fluidcommunication with the flowbore 34 and the casing flowpath 82. Thepiston head 86 of the upper piston 80 may be disposed in the casingflowpath 82 and subjected to an initial pressure of the flowbore 34. Inan exemplary embodiment, the initial pressure may be the hydrostaticpressure in the wellbore 10. In the initial position, the initialpressure is less than the first threshold pressure. As shown in FIGS. 2Aand 2B and FIGS. 3A and 3B, the piston rod 88 may be coupled or integralwith the annular cover 74 and thereby may be configured to displace theannular cover 74 dependent on pressure applied to the piston head 86. Atthe initial pressure, the applied pressure to the piston head 86 is notsufficient to cause the piston rod 88 to displace the annular cover 74from the location depicted in FIGS. 2A and 2B and FIGS. 3A and 3B.Accordingly, the annular cover 74 may be retained in the initialposition via the shear screws 96 retained by the first annular component70 (or annular cover 74 as shown in FIGS. 3A and 3B).

In the embodiment illustrated in FIGS. 2A and 2B, the annular cover 74may be positioned such that the annular cover 74 seals the flowbore 34from the annular space 64. To do so, the annular cover 74 in the initialposition may be positioned over the second port 98, such that arespective seal component 76, 78 may be disposed between the annularcover 74 and the inner annular casing 46 on either side of the secondport 98. Accordingly, the initial pressure in the flowbore 34 may beapplied only to the casing flowpath 82 and the upper piston 80 via thefirst port 90 in the initial position as shown in FIGS. 2A and 2B andFIGS. 3A and 3B.

The second end portion 104 of the annular cover 74 may be detachablyattached to the locking ring 72 as shown in FIGS. 2A and 2B and FIGS. 3Aand 3B. Although illustrated as a unitary component, the annular cover74 may be formed from a plurality of components. As shown in theembodiment of FIGS. 2A and 2B, the second end portion 104 of the annularcover 74 may define an annular cover flowpath 108 fluidly coupled to theportion of the pressurized chamber formed between the annular cover 74and the lower piston 48 disposed in the annular space 64. In anexemplary embodiment, the pressurized chamber may be at aboutatmospheric pressure (1 atm); however, the pressurized chamber may be atpressures greater than atmospheric pressure depending on the spring rateof the spring 68.

The locking ring 72 may be a circlip, snap ring, or any other retainingring capable of retaining the annular cover 74 in the initial position.The locking ring 72 may be disposed and seated on the shoulder 102formed on the first annular component 70 in the initial position. Thelocking ring 72 may utilize the support of the shoulder 102 to counterthe forces provided by the spring 68 against the annular cover 74retained by the locking ring 72.

The spring 68 may apply a force consistent with the spring rate and thelocation of the biasing nut 66 in the pressurized chamber of the annularspace 64. The spring rate and the placement of the biasing nut 68 may bedetermined based in part on at least one of the first thresholdpressure, the third threshold pressure, and the pressure in thepressurized chamber of the annular space 64. In the initial position,the spring 68 may apply a force to the annular cover 74; however, theforce provided by the spring 68 based on the aforementioned parametersmay not be sufficient to displace the annular cover 74 based at least onthe locking ring 72 being disposed and seated on the shoulder 102 of thefirst annular component 70.

The lower piston 48 is depicted in FIGS. 2A and 2B and FIGS. 3A and 3Bin the initial position covering the housing apertures 41 defined in thehousing 36, thereby preventing fluid communication between the casingstring 12 and the subterranean formation 20 or wellbore 10, or both. Inthe initial position, the first end portion 52 of the lower piston 48may be disposed in the pressurized chamber of the annular space 64 andmay be seated on the second end portion 54 of the inner annular casing46. As the first end portion 52 of the lower piston 48 is subjected tothe pressure of the pressurized chamber of the annular space 64, asufficient force may not be applied to the first end portion 52 of thelower piston 48 to displace the lower piston 48 in the annular space 64.

After the casing string 12 and downhole completion tool 18 are run inthe wellbore 10, a pressure test may be performed. Accordingly, a firstthreshold pressure may be applied to the casing string 12 and thedownhole completion tool 18 as depicted in FIGS. 2C and 2D and FIGS. 3Cand 3D, according to at least some embodiments of the presentdisclosure. In this position, the downhole completion tool 18 may bereferred to as being in a first threshold position. The first thresholdpressure may be substantially equal to or less than the casing testpressure or the rated casing pressure. In an exemplary embodiment, thefirst threshold pressure is about seventy percent of the casing testpressure. In another embodiment, the first threshold pressure is aboutseventy percent of the casing test pressure. In another embodiment, thefirst threshold pressure is about seventy-five percent of the casingtest pressure. In another embodiment, the first threshold pressure isabout eighty percent of the casing test pressure. In another embodiment,the first threshold pressure is about eighty-five percent of the casingtest pressure. In another embodiment, the first threshold pressure isabout ninety percent of the casing test pressure. In another embodiment,the first threshold pressure is about ninety-five percent of the casingtest pressure. One of ordinary skill in the art will appreciate that thecasing test pressure may be dependent at least in part on the ratedcasing pressure, and accordingly, the casing test pressure chosen forthe pressure test may vary depending on the casing string 12 utilized inthe wellbore 10.

As the first threshold pressure is applied to the casing string 12 andthe downhole completion tool 18 via fluid pumped through the casingstring 12 from the surface 22, fluid is flowed through the first port 90causing a force correlating to the first threshold pressure to beapplied to the piston head 86 of the upper piston 80 disposed in thecasing flowpath 82. The force is sufficient to displace the annularcover 74 via the piston rod 88 and to shear the shear screws 96retaining the annular cover 74 in the initial position. As the annularcover 74 is axially displaced, the locking ring 72 coupled to the secondend portion 104 of the annular cover 74 is axially displaced downstreamfrom the seated position on the shoulder 102 of the first annularcomponent 70 and is axially shifted along the first annular component70. As the locking ring 72 reaches the lip 106 of the first annularcomponent 70, the locking ring 72 expands and presses against an innersurface 50 of the housing 36 and abuts or is seated on the lip 106 ofthe first annular component 70 such that the locking ring 72 isprohibited from moving axially upstream. As the locking ring 72 expands,the locking ring 72 detaches from the second end portion 104 of theannular cover 74, such that the annular cover 74 and the locking ring 72are no longer attached to one another. The annular cover 74 may beretained adjacent the locking ring 72 seated on the lip 106 of the shearring 70 until the application of the first threshold pressure is ceasedand the pressure in the flowbore 34 begins to bleed down.

In the first threshold position, the annular cover 74 may be urged bythe upper piston 80 with a magnitude of force sufficient to furthercompress the spring 68 in the position as indicated in FIGS. 2C and 2Dand FIGS. 3C and 3D, thereby providing stored mechanical energy to thespring 68. In the first threshold position, the annular cover 74 may beaxially displaced to expand the locking ring 72 and decouple the lockingring 72 from the annular cover 74; however, the annular cover 74 mayremain positioned over the second port 98, such that a respective seal76, 78 may be disposed between the annular cover 74 and the innerannular casing 46 on either side of the second port 98, as shown in theembodiment of FIGS. 2C and 2D. Accordingly, the first threshold pressurein the flowbore 34 may be applied only to the casing flowpath 82 andupper piston 80 via the first port 90 in the first threshold position.

As the first threshold pressure in the flowbore 34 may be applied onlyto the casing flowpath 82 and upper piston 80 via the first port 90 inthe first threshold position, the pressurized chamber may remain atatmospheric pressure. Accordingly, the lower piston 48 may remainstatically disposed and seated on the shoulder 56 of the second endportion 54 of the inner annular casing 46. In the first thresholdposition, the lower piston 48 prevents fluid communication between thehousing apertures 41 and the flowbore 34 of the downhole completion tool18. Thus, the downhole completion tool 18 may allow for a pressure buildup in the flowbore 34 indicative of a pressure test without allowing forany leakage or flow to and/or from the subterranean formation 20 in thefirst threshold position.

After performing the pressure test and achieving the first thresholdpressure in the downhole completion tool 18 and the casing string 12,the first threshold pressure may be allowed to bleed down to reduce thepressure in the downhole completion tool 18 and casing string 12 to ableed down pressure, or second threshold pressure. As positioned in thewellbore 10 after the pressure has been bled down from the firstthreshold pressure to the second threshold pressure, the downholecompletion tool 18 may be configured as depicted in FIGS. 2E and 2F andFIGS. 3E and 3F. Accordingly, the downhole completion tool 18 may bereferred to as being in a “bled down” or second threshold position. Inthe second threshold position, the pressure in the downhole completiontool 18 may be reduced to a second threshold pressure having a pressureat or substantially equal to the initial pressure in the wellbore 10. Inanother embodiment, the pressure in the downhole completion tool 18 maybe reduced to a second threshold pressure having a pressure at orsubstantially equal to the hydrostatic pressure in the wellbore 10. Inother embodiments, the pressure in the downhole completion tool 18 maybe reduced to a second threshold pressure having a pressure at orsubstantially equal to about 0 psig, about 250 psig, about 500 psig,about 750 psig, about 1000 psig, about 1250 psig, or about 1500 psig.

As shown in FIGS. 2E and 2F and FIGS. 3E and 3F, as the pressure is bleddown to the second threshold pressure, the mechanical energy stored inthe spring 68 may be released in the form of a force applied to thesecond end portion 104 of the annular cover 74, which may be greaterthan the force applied to the piston head 86 by the pressure of thefluid flowing through the casing flowpath 82 via the first port 90.Accordingly, the spring 68 may decompress or expand from the state ofthe spring 68 in the first threshold position. As the spring 68decompresses, the spring 68 applies a force to the annular cover 74thereby retracting or displacing the annular cover 74 upstream in anaxial direction. The annular cover 74 may be axially displaced upstreamand prohibited from further axial movement upstream by the first subcomponent 30. In this location, the annular cover 74 is disposed in thecasing flowpath 82 as depicted in FIGS. 2E and 2F and FIGS. 3E and 3F.

As shown in the embodiment of FIGS. 2E and 2F, in the second thresholdposition, the spring 68 may expand and retain the annular cover 74 incontact with or adjacent the first sub component 30 such that fluid maybe prevented or substantially restricted from flowing into the casingflowpath 82 via the first port 90. Accordingly, in the second thresholdposition, the second end portion 104 of the annular cover 74 may bedisposed in the downhole completion tool 18 such that the annular coverflowpath 108 defined in the annular cover 74 may be substantiallyaligned with the second port 98 of the inner annular casing 46 such thatthe annular cover flowpath 108 may be in fluid communication with theflowbore 34 via the second port 98. Correspondingly, as the annularcover flowpath 108 may be in fluid communication with the pressurizedchamber of the annular space 64, the flowbore 34 may be in fluidcommunication with the pressurized chamber via the second port 98 andthe annular cover flowpath 108. The pressurized chamber may be at apressure less than or substantially equal to the pressure in theflowbore 34 and the casing string 12 of the downhole completion tool 18,such that there may be no pressure differential or there may be apositive pressure differential from the pressure in the flowbore 34 andthe casing string 12 of the downhole completion tool 18 to thepressurized chamber.

In the embodiment illustrated in FIGS. 3E and 3F, in the secondthreshold position, the spring 68 may expand and retain the annularcover 74 in contact with or adjacent the first sub component 30;however, fluid may be permitted to flow into the casing flowpath 82 viathe first port 90. Accordingly, in the second threshold position, thecasing flowpath 82 may be in fluid communication with the fluidpassageway 97 defined between the annular cover 74 and the first annularcomponent 70 such that fluid may flow via the first port 90 into thecasing flowpath 82 and through the fluid passageway 97 into the annularspace 64. Thus, the flowbore 34 may be in fluid communication with thepressurized chamber of the annular space 64 via the first port 90, thecasing flowpath 82, and the fluid passageway 97. The pressurized chambermay be at a pressure less than or substantially equal to the pressure inthe flowbore 34 and the casing string 12 of the downhole completion tool18, such that there may be no pressure differential or there may be apositive pressure differential from the pressure in the flowbore 34 andthe casing string 12 of the downhole completion tool 18 to thepressurized chamber.

As depicted in FIGS. 2E and 2F and FIGS. 3E and 3F, the pressure in thepressurized chamber in the second threshold position may be insufficientto displace the lower piston 48 partially disposed in the annular space64. The lower piston 48 may be retained in place by the shear screws 62,which may be rated to retain the lower piston 48 in the second thresholdposition until the third threshold pressure is reached in thepressurized chamber. Accordingly, in the second threshold position, thelower piston 48 may be positioned in the downhole tool 18 to prohibitfluid flowing through the casing string 12 and flowbore 34 fromcommunicating with the subterranean formation 20 via the housingapertures 41. Corresponding, in the second threshold position, the lowerpiston 48 may be positioned in the downhole tool 18 to prohibit fluidflowing through the subterranean formation 20 from communicating withthe casing string 12 and flowbore 34 via the housing apertures 41.

Thus, as depicted in FIGS. 2E and 2F and FIGS. 3E and 3F, portions ofthe downhole completion tool 18 may be arranged accordingly afterundergoing a pressure cycle including a first threshold pressureconsistent with or in the range of a pressure associated with a pressuretest to evaluate for leaks or openings in the casing string 12 anddownhole completion tool 18. As configured in the second thresholdposition, the downhole completion tool 18 may be referred to as “armed”and capable of providing a flowpath to and/or from the subterraneanformation 20 after the application of the third threshold pressurewithout an additional trip down hole by the operator. By eliminating anadditional trip downhole, the downhole completion tool 18 as describedherein provides for a reduction in time completing the well andcorresponding savings in financial resources.

After the third threshold pressure may be applied to the casing string12 and the downhole completion tool 18 in the second pressure cycle, thedownhole completion tool 18 may be configured as depicted in therespective embodiments of FIGS. 2G and 2H and FIGS. 3G and 3H.Accordingly, the downhole completion tool 18 may be referred to as beingin a “flowthrough” or final position. In the final position, theflowbore 34 of the downhole completion tool 18 may be in fluidcommunication with the subterranean formation 20 or the wellbore 10, orboth, via the housing apertures 41, thereby allowing for the stimulationof the subterranean formation 20 and/or the retrieval of hydrocarbonsfrom the subterranean formation 20.

The arrangement of the downhole completion tool 18 as depicted in FIGS.2G and 2H and FIGS. 3G and 3H in the final position may be accomplishedby providing the third threshold pressure to the downhole completiontool 18 as arranged in FIGS. 2E and 2F and FIGS. 3E and 3F,respectively, in the second threshold position. Accordingly, the thirdthreshold pressure may be applied to the casing string 12 and downholecompletion tool 18 via fluid provided from the surface 22 and pumpeddownhole via one or more pumps. The third threshold pressure may begreater than the pressure in the wellbore 10 after the wellbore 10 isbled down to the second threshold pressure from the first thresholdpressure.

The third threshold pressure may be determined at least in part bydesign parameters, including, for example, the rating of the shearscrews 62 retaining the lower piston 48 in place and the pressure in thepressurized chamber of the annular space 64. In another embodiment, thethird threshold pressure may be determined at least in part by thecharacteristics of the subterranean formation 20, e.g., type of rock,porosity, and permeability. In an operative example, the third thresholdpressure may be at least about 2000 psig. In another operative example,the third threshold pressure may be at least about 500 psig. Still yet,in other operative examples, the third threshold pressure may be atleast about 1000 psig, at least about 1500 psig, at least about 2500psig, at least about 3000 psig, at least about 3500 psig, at least about4000 psig, at least about 4500 psig, or at least about 5000 psig.

In an exemplary embodiment, the third threshold pressure may be appliedto the casing string 12 and the downhole completion tool 18, such thatthe third threshold pressure is greater than the pressure in thepressurized chamber. Accordingly, the third threshold pressure may beintroduced to the pressurized chamber via the second port 98 and theannular cover flowpath 108 as illustrated in FIGS. 2G and 2H. In anotherembodiment illustrated in FIGS. 3G and 3H, the third threshold pressuremay be introduced to the pressurized chamber via the first port 90, thecasing flowpath 82, and the fluid passageway 97. In the embodimentsillustrated in FIGS. 2G and 2H and FIGS. 3G and 3H, the correspondingpressure in the pressurized chamber allows for the application of aforce against the first end portion 52 of the lower piston 48. The forceproduced by the applied third threshold pressure may be of sufficientmagnitude to displace the lower piston 48, thereby shearing the shearscrews 62 retaining the lower piston 48 in a fixed position. The forcemay axially displace the lower piston 48 in the downstream directionsuch that the lower piston 48 may contact or at least may be adjacentthe second sub component 32. The force provided by the applied thirdthreshold pressure may retain the lower piston 48 in contact with oradjacent the second sub component 32.

The displacement of the lower piston 48 in the downstream axialdirection allows for the fluid communication of the flowbore 34 of thedownhole completion tool 18 with the subterranean formation 20 orwellbore 10, or both, via the housing apertures 41. In the finalposition, stimulants and/or production fluid may flow therebetween viathe housing apertures 41. Thus, the downhole completion tool 18 asdescribed herein provides for the application of a pressure test and asubsequent fluid pathway for stimulation and/or production of thehydrocarbon well without the requirement of separate trips downhole.

In another embodiment, the casing string 12 may include a plurality ofdownhole completion tools 18 coupled with one another in series,commonly referred to as “daisy-chained.” In another embodiment, thedownhole completion tools 18 may be separated by portions of the casingstring 12. By arranging the downhole completion tools 18 in series alonga portion of the casing string 12, multiple pressure tests may beconducted before the production or stimulation of the well withoutfurther trips downhole. Thus, multiple pressure cycles may be providedin instances in which two or more pressure tests may be required.

As shown in FIG. 4, a method 200 for servicing a subterranean formationis provided, according to one or more embodiments of the presentdisclosure. The method 200 may include applying a first pressure to afirst piston via a first port defined in an inner annular casing of adownhole tool including a housing at least partially defining a flowboreextending axially therethrough and in fluid communication with the firstport, as at 202. The method 200 may also include displacing an annularcover axially via a force generated by the first pressure on the firstpiston, the annular cover shearing a first retention member configuredto retain the annular cover prior to the application of the firstpressure, as at 204. The method 200 may further include displacing alocking ring detachably attached to the annular cover, such that thelocking ring detaches from the annular cover, as at 206.

The method 200 may also include decreasing the first pressure to asecond pressure such that the annular cover is axially displaced and theflowbore is fluidly coupled with an annular space defined at least inpart by the housing and the inner annular casing, as at 208. The method200 may also further include applying a third pressure to the annularspace via the flowbore, as at 210. The method may further includedisplacing a second piston axially via a force generated by the thirdpressure on the second piston, the second piston shearing a secondretention member configured to retain the second piston prior to theapplication of the third pressure, thereby fluidly coupling thesubterranean formation and the flowbore via a plurality of housingapertures defined in the housing, as at 212.

The foregoing has outlined features of several embodiments so that thoseskilled in the art may better understand the present disclosure. Thoseskilled in the art should appreciate that they may readily use thepresent disclosure as a basis for designing or modifying other processesand structures for carrying out the same purposes and/or achieving thesame advantages of the embodiments introduced herein. Those skilled inthe art should also realize that such equivalent constructions do notdepart from the spirit and scope of the present disclosure, and thatthey may make various changes, substitutions and alterations hereinwithout departing from the spirit and scope of the present disclosure.

We claim:
 1. A downhole tool, comprising: a housing having alongitudinal axis and defining a plurality of fluid aperturescircumferentially disposed about the longitudinal axis; an inner annularcasing disposed in the housing and defining a flowbore extending axiallytherethrough, the housing and the inner annular casing defining anannular space therebetween, and the inner annular casing furtherdefining a casing flowpath and a port configured to fluidly couple theflowbore and the casing flowpath; a first piston disposed in the casingflowpath; an annular sleeve disposed in the annular space and coupled toor integral with the first piston, the annular sleeve configured to bedisplaced in a first direction by the first piston at a first pressureapplied to the flowbore; a biasing member disposed in the annular spaceand configured to displace the annular sleeve in a second direction at asecond pressure applied to the flowbore; and a second piston at leastpartially disposed in the annular space and configured to be displacedin the first direction by a third pressure applied to the annular spacevia the flowbore, such that the plurality of fluid apertures and theflowbore are fluidly coupled.
 2. The downhole tool of claim 1, whereinthe second piston is disposed downstream from the annular sleeve and isslidingly engaged with the housing.
 3. The downhole tool of claim 1,wherein the biasing member is disposed about the inner annular casingand downstream from the annular sleeve.
 4. The downhole tool of claim 3,further comprising a biasing nut disposed in the annular space, suchthat the biasing member is disposed between the annular sleeve and thebiasing nut.
 5. The downhole tool of claim 4, wherein the downhole toolis configured such that the annular sleeve compresses the biasing memberas the first pressure is applied to the flowbore.
 6. The downhole toolof claim 1, further comprising a plurality of seal components configuredto retain the annular space at about atmospheric pressure as the firstpressure is applied to the flowbore.
 7. The downhole tool of claim 1,further comprising a first retention member configured to retain theannular sleeve in a fixed position.
 8. The downhole tool of claim 7,further comprising a second retention member configured to fixedlyretain the second piston prior to the application of the third pressureto the flowbore.
 9. A method of servicing a subterranean formation,comprising: applying a first pressure to a first piston via a flowboredefined at least in part by an inner annular casing of a downhole tool,the downhole tool comprising a housing encircling the inner annularcasing such that an annular space is defined therebetween; displacing anannular sleeve coupled to or integral with the first piston in a firstdirection via a force provided by the first pressure applied to thefirst piston; decreasing the first pressure in the flowbore to a secondpressure such that the annular sleeve is displaced in a seconddirection; applying a third pressure to the annular space via theflowbore; and displacing a second piston in the first direction via aforce provided by the third pressure applied to the second piston,thereby fluidly coupling the subterranean formation and the flowbore viaa plurality of housing apertures defined in the housing andcircumferentially disposed about the inner annular casing.
 10. Themethod of claim 9, wherein: the inner annular casing further defines aport and a casing flowpath in fluid communication with the flowbore viathe port; and the casing flowpath is in fluid communication with theannular space upon application of the third pressure.
 11. The method ofclaim 10, wherein decreasing the first pressure in the flowbore to thesecond pressure such that the annular sleeve is displaced in the seconddirection further comprises biasing the annular sleeve toward the portvia a biasing member at the second pressure, the biasing member disposedabout the inner annular casing and in the annular space.
 12. The methodof claim 11, wherein the first piston is disposed within the casingflowpath, and the annular sleeve is disposed within the annular space.13. The method of claim 9, further comprising disposing the downholetool in a wellbore defined in the subterranean formation via a tubularmember.
 14. The method of claim 13, further comprising sealing theannular space prior to disposing the downhole tool in the wellbore, suchthat a fluid sealed in the annular space is at about atmosphericpressure.
 15. The method of claim 9, wherein displacing the secondpiston in the first direction via the force provided by the thirdpressure applied to the second piston further comprises shearing aretention member configured to retain the second piston in a fixedposition prior to the application of the third pressure.
 16. A methodfor conducting multiple pressure tests of a casing string disposed in awellbore, comprising: applying a first pressure to a first piston via aflowbore defined at least in part by an inner annular casing of adownhole tool, the downhole tool coupled to the casing string such thatthe downhole tool forms a portion of the casing string, and the downholetool comprising a housing encircling the inner annular casing such thatan annular space is defined therebetween; displacing an annular sleevecoupled to or integral with the first piston in a first direction via aforce provided by the first pressure applied to the first piston;decreasing the first pressure in the flowbore to a second pressure suchthat the annular sleeve is displaced in a second direction; applyingadditional pressures to the annular space via the flowbore; anddisplacing, in the first direction, a second piston disposed in thecasing string via a force provided by one pressure of the additionalpressures applied to the second piston, thereby fluidly coupling thewellbore and the flowbore via a plurality of apertures defined in thecasing string and circumferentially disposed about a longitudinal axisthereof.
 17. The method of claim 16, wherein the inner annular casingfurther defines a port and a casing flowpath in fluid communication withthe flowbore via the port.
 18. The method of claim 17, whereindecreasing the first pressure in the flowbore to the second pressuresuch that the annular sleeve is displaced in the second directionfurther comprises biasing the annular sleeve toward the port via abiasing member at the second pressure, the biasing member disposed aboutthe inner annular casing and in the annular space.
 19. The method ofclaim 18, wherein the first piston is disposed within the casingflowpath, and the annular sleeve is disposed within the annular space.20. The method of claim 16, wherein displacing, in the first direction,the second piston disposed in the casing string via the force providedby the one pressure of the additional pressures applied to the secondpiston further comprises shearing a retention member configured toretain the second piston in a fixed position prior to the application ofthe one pressure.